Systems and methods for artificially lifting a product from a well

ABSTRACT

Systems and methods for providing a pump driving unit for driving an above ground pump. The pump driving unit utilizes a single prime mover and a drive train for actuating multiple components required to drive the above ground pump. Some implementations of the pump driving unit include phase separation devices, filtering units, and cooling units that may also be actuated by the drive train of the unit. Some implementations of the pump driving unit further include an enclosure and a platform for containing the unit and simplifying on-site installation.

RELATED APPLICATIONS

This application is a continuation in part of co-pending utility application Ser. No. 12/495,926 filed Jul. 1, 2010, entitled “SYSTEM AND METHODS FOR DRIVING A PUMPJACK” which is a continuation in part of co-pending utility application Ser. No. 12/202,108 filed Aug. 29, 2008, entitled “SYSTEMS AND METHODS FOR DRIVING A SUBTERRANEAN PUMP”, both of which are incorporated herein by reference, in their entireties.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to a low emission system for reciprocating a natural gas/oil well pumpjack associated with a subterranean well. In particular, the present invention relates to systems and methods for providing modular and combination units capable of driving a hydraulic pump or motor which in turn drives a pumpjack, as well as other components of the system, as required to produce the well. The present invention further relates to systems and methods for providing modular and combinations unit capable of driving a subterranean pump associated with a subterranean well.

2. Background and Related Art

Oil wells typically vary in depth from a few hundred feet, to several thousand feet. In many wells there is insufficient subterranean pressure to force the oil and water to the earth's surface. For this reason, some system must be used to pump the crude oil, hydrocarbon gas, produced water and/or hydrocarbon liquids of the producing formation to the earth's surface. The most common system for pumping an oil well is by the installation of a pumping unit at the earth's surface that vertically reciprocates a travelling valve of a subsurface pump.

Traditionally, subsurface pumps have been reciprocated by a pumping device called a pumpjack which operates by the rotation of an eccentric crank driven by a prime mover which may be an engine or an electric motor. A mechanical mechanism such as this has been utilized extensively in the oil and natural gas production industry for decades and continues to be a primary method for extracting oil from a well.

In addition to lifting gas and/or oil from the producing formation, traditional pumping systems further provide means for separating, compressing, cooling, and storing materials recovered from the associated well. The function of lifting the gas and/or oil, combined with the additional functions of separating, compressing, cooling and storing the lifted materials requires the use of multiple prime movers, motors, generators, power supplies and the like. The various prime movers or motors each require fuel and maintenance, as well as produce emissions. Thus, such mechanical systems suffer from a number of inherent disadvantages or inefficiencies which are undesirable.

While techniques currently exist that relate to driving a pumpjack, challenges still exist. A need, therefore, exists for a dynamic pump driving system that overcomes the current challenges. Accordingly, it would be an improvement in the art to augment or even replace current techniques with other techniques.

SUMMARY OF THE INVENTION

The present invention relates to reciprocating an oil or natural gas pumpjack associated with a subterranean well. In particular, the present invention relates to systems and methods for providing a dynamic, combination unit capable of driving a hydraulic portion of a pumpjack system, as well as other components of the system, as required. The present invention further relates to driving a subterranean pump associated with a subterranean well.

Implementation of the present invention takes place in association with an artificial lift system for recovery of oil and/or gas from a subterranean well. In some implementations, the combination pump drive includes a prime mover, a hydraulic pump or motor, and a compressor. The combination unit further includes a drive train having a jack shaft interconnected to a plurality of pulleys and belts whereby the single prime mover drives the various components of the combination unit. The combined configuration of the prime mover and the drive train eliminates the need for multiple prime movers or motors to operate the various components of the unit. Thus, a single prime mover is used to simultaneously and efficiently drive the components of the unit, which in turn drives the pumpjack associated within a subterranean well. For example, in one embodiment a single prime mover is used to drive both the pumpjack and simultaneously perform other tasks, such as compressing and cooling the gas at the surface prior to storage.

In at least some implementations of the present invention, the combination unit includes an oil-field separator, a filtration unit, a cooling unit, and a storage tank. The oil-field separator is interposed between the wellhead and the compressor to separate the various phases of materials lifted from the subterranean well. In some implementations the filtration unit is interposed between the separator and the compressor to remove undesirable debris and particulate matter prior to compression. In still further implementations, the cooling unit is interposed between the filtration unit and the storage tank to sufficiently cool the compressed natural gas prior to storage. The storage tank is provided to receive and store the lifted gases and liquids, as required by the unit.

In at least some implementations, the combination unit further includes an enclosure and a platform to contain the various components of the system. Additional features may include a battery and/or an alternative energy source to power the prime mover during operation of the unit.

While the methods, modifications and components of the present invention have proven to be particularly useful in the area oil and/or gas production, those skilled in the art will appreciate that the methods, modifications and components can be used in a variety of different artificial lift applications.

These and other features and advantages of the present invention will be set forth or will become more fully apparent in the description that follows and in the appended claims. The features and advantages may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. Furthermore, the features and advantages of the invention may be learned by the practice of the invention or will be obvious from the description, as set forth hereinafter.

BRIEF DESCRIPTION OF THE DRAWINGS

In order that the manner in which the above recited and other features and advantages of the present invention are obtained, a more particular description of the invention will be rendered by reference to specific embodiments thereof, which are illustrated in the appended drawings. Understanding that the drawings depict only typical embodiments of the present invention and are not, therefore, to be considered as limiting the scope of the invention, the present invention will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 is a perspective side view of a representative embodiment of the present invention;

FIG. 2 is a perspective top view of the combination unit of claim 1;

FIG. 3 is a cross-sectional view of a representative hydraulic line of an embodiment of the present invention;

FIG. 4 is a perspective side view of a representative embodiment of the present invention;

FIG. 5 is a perspective side view of a representative embodiment of a modular pump driving system of the present invention;

FIG. 6 is a perspective side view of a representative embodiment of a combination pump driving system of the present invention;

FIG. 7 is a perspective side view of a representative embodiment of a combination pump driving system of the present invention; and

FIG. 8 is a perspective view of representative embodiment of a direct drive pump driving unit in accordance with a representative embodiment of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention relates to reciprocating an oil or natural gas pumpjack associated with a subterranean well. In particular, the present invention relates to systems and methods for providing a dynamic, combination unit capable of driving a hydraulic portion of a pumpjack system, as well as other components of the system, as required. The present invention further relates to driving a subterranean pump associated with a subterranean well.

It is emphasized that the present invention, as illustrated in the figures and description herein, may be embodied in other forms. Thus, neither the drawings nor the following more detailed description of the various embodiments of the system and method of the present invention limit the scope of the invention. The drawings and detailed description are merely representative of examples of embodiments of the invention; the substantive scope of the present invention is limited only by the appended claims recited to describe the many embodiments. The various embodiments of the invention will best be understood by reference to the drawings, wherein like elements are designated by like alphanumeric character throughout.

Referring now to FIG. 1, an implementation of a combination pump driving unit 10 is shown. The combination unit 10 generally comprises a prime mover 20, a hydraulic pump 30, and a compressor 40, as shown. Additionally, the combination unit 10 comprises a drive train 50 whereby the prime mover 20 actuates the various components 30 and 40 of the unit 10.

Referring now to FIGS. 1 and 2, the prime mover 20 may include any device capable of driving the drive train 50 of the unit 10. For example, in one embodiment the prime mover 20 is a natural gas powered engine having an exhaust pipe 28. In another embodiment, the prime mover 20 is an electric motor, as shown in FIGS. 4-7. In some embodiments, the prime mover 20 comprises at least one of a gas turbine, a steam turbine, a water turbine, a diesel engine, and a petrol engine. In each embodiment, the prime mover 20 further comprises a rotor 22 extending outwardly from the body of the prime mover 20. The rotor 22 is positioned and configured so as to compatibly receive a pulley 24, discussed in detail below.

In embodiments where the prime mover 20 is an electric motor, as shown in FIG. 4-7, the prime mover 20 may be powered by any electric source producing sufficient wattage and amperage, as required. For example, in one embodiment the prime mover 20 is hardwired to an electrical line 76. In another embodiment, the prime mover 20 is powered by a battery 96 via a power cord 98. The battery 96 may include any battery commonly known in the art including galvanic cells, electrolytic cells, fuel cells, and voltaic piles. Additionally, the battery 96 may comprise primary batteries or secondary batteries, as required by the unit 10. Where the battery 96 comprises secondary batteries, the battery 96 may be recharged by applying electrical current to the battery 96 via a charging source 94. The charging source may include any alternate source of electricity such as a wind-powered generator, a solar-powered generator, a hydro-powered generator, a geothermal-powered generator, or a generator powered by a second prime mover (not shown). In one embodiment, the battery 96 is charged via a generator or alternator (not shown) that is driven by the drive train 50 of the unit.

Additional components of the unit may include a hydraulic pump 30 and a compressor 40. The hydraulic pump 30 is well known in the art and in some embodiments may be modified to enhance the pump's operation or efficiency. For example, in one embodiment the hydraulic pump 30 is a hydrostatic pump. In another embodiment the hydraulic pump 30 is hydrodynamic. In one embodiment where the hydraulic pump 30 is hydrostatic, the displacement of the pump is fixed, such that the displacement through the pump 30 cannot be adjusted. In another embodiment where the hydraulic pump 30 is hydrostatic, the displacement of the pump is variable, such that the displacement through the pump 30 is adjustable. Additional embodiments of the hydraulic pump 30 include a gear pump, a gerotor pump, a rotary vane pump, a screw pump, a bent axis pump, an axial piston pump, a radial piston pump, and a peristaltic pump. In some embodiments, a jet pump (not shown) is substituted for the hydraulic pump 30.

The hydraulic pump 30 is provided to drive a hydraulic cylinder portion (not shown) of a down hole oil pump, or subterranean pump as commonly used in the oil industry. As such, the hydraulic pump 30 typically requires approximately 0-5000 psig to sufficiently drive the subterranean pump. Various forms and combinations of subterranean pumps are available and commonly used, as will be appreciated by one of ordinary skill in the art. For example, in one embodiment the subterranean pump includes a hydraulic cylinder portion that is located or enclosed within the wellhead 12 and is accessible via the hydraulic port 14. In another embodiment, the subterranean pump includes a hydraulic cylinder portion that is located at the bottom of the well and is accessible via hydraulic lines connecting the hydraulic pump and the hydraulic cylinder. The hydraulic pump 30 is fluidly coupled to the hydraulic port 14 via a hydraulic line 80. The hydraulic line 80 is provided to circulate hydraulic fluid from the hydraulic pump 30 to the subterranean pump via the hydraulic port 14 and wellhead 12.

Referring now to FIG. 3, a cross-sectional view of an implementation of the hydraulic line 80 is shown. The hydraulic line 80 comprises an outer tubing 82 and an inner tubing 84, the inner tubing 84 being entirely encased within the outer tubing 82. The inner tubing 84 comprises a lumen 88 of sufficient diameter to permit flow of hydraulic fluid to the subterranean pump. As such, the inner tubing 84 acts as an egress line from the hydraulic pump 30. Similarly, the outer tubing 82 comprises an inner lumen 86 of sufficient diameter to both house the inner tubing 84 and permit flow of hydraulic fluid from the subterranean pump to the hydraulic pump 30. As such, the outer tubing 82 acts as an ingress line into the hydraulic pump 30. The diameters of the outer tubing 82 and the inner tubing 84 may be configured as needed to provide sufficient supply of hydraulic fluid to the hydraulic components of the subterranean pump. For example, in one embodiment the outer tubing 82 has an inner diameter of approximately 38 mm while the inner tubing has an inner diameter of approximately 19 mm. One of skill in the art will appreciate that the wellhead 12, the hydraulic cylinder, and the hydraulic pump 30 may be modified to accommodate multiple hydraulic lines in place of the combination hydraulic line 80, as disclosed and shown in connection with FIG. 5, below.

Referring again to FIGS. 1 and 2, the unit 10 further comprises a compressor 40. The compressor 40 is a well known component in the art of oil production, and is provided to compress hydrocarbon gases following extraction from the well. The compressor 40 may include any device capable of increasing the pressure of gas removed from the well by reducing the volume of the gas. For example, in one embodiment the compressor 40 includes at least one of a reciprocating compressor, a diaphragm compressor, a diagonal compressor, a mixed-flow compressor, an axial-flow compressor, a centrifugal compressor, a rotary screw compressor, a rotary vane compressor, and a scroll compressor.

The compressor 40 is provided to draw gas from the wellhead 12 via a gas line 90 and then compress the gas to optimize natural gas production and increase flow from the well. The gas line 90 is generally configured to be in fluid communication with the wellhead such that any gas brought to the wellhead via suction provided by the compressor 40 is directed into the gas line 90 and subsequently drawn into the compressor 40. Following compression, the compressed gas exits the compressor 40 through a second gas line 92 and is deposited into a pipeline or a storage container or collection tank 110. One of skill in the art will appreciate that the collection tank 110 may comprise any size and dimensions necessary to accommodate the oil and gas production of the unit 10. For example, in one embodiment the collection tank 110 is an underground storage tank in fluid communication with the compressor 40 via the second gas line 92.

With continued reference to FIGS. 1 and 2, the various components 30 and 40 of the unit 10 are actuated by the prime mover 20 via the drive train 50. The drive train 50 generally comprises a system of interconnected pulleys and belts to link the prime mover 20 to the remaining components 30 and 40 of the unit 10. However, in some implementations of the present invention, the drive train 50 is directly coupled to the driving components 30 and 40 of the unit 10 without the use of a jack shaft or pulleys. As illustrated, the central feature of the drive train 50 is a jack shaft 52, as best shown in FIG. 2. The jack shaft 52 is generally located at a central position between the various components of the unit 10. The jack shaft 52 generally comprises a steel or otherwise metallic material rod having a length sufficient to accommodate the various positions of the components of the unit 10. The jack shaft 52 is rotatably secured to the enclosure 70 or the skid 72 by means of a stator 74. A set of bearings (not shown) is interposed between the stator 74 and the jack shaft 52 so as to permit rotation of the jack shaft 52 relative to the stator 74.

The jack shaft 52 further comprises a master pulley 54 fixedly attached to the jack shaft 52 at a position approximately in the same plane as a rotor 22 and pulley 24 of the prime mover 20. The master pulley 54 and the pulley 24 of the prime mover 20 are interconnected via a belt or chain 26, thereby forming a primary section 60 of the drive train 50. As configured, the torque of the prime mover 20 is transferred to the master pulley 54 via the pulley 24 and belt 26 thereby causing the jack shaft 52 to rotate relative to the stators 74. One of ordinary skill in the art will appreciate that by varying the sizes of the master pulley 54 and the prime mover 20 pulley 24, the relative rotations per minute of the jack shaft 52 may be adjusted to accommodate the needs of the unit 10. Additionally or alternatively, the relative rotations per minute of the jack shaft 52 may be altered by varying the rotations per minute of the prime mover 20, as commonly understood in the art.

In addition to the master pulley 54, the jack shaft 52 further comprises a plurality of slave pulleys 56 and 58. The slave pulleys 56 and 58 are fixedly attached to the jack shaft 52 at a position generally in the same plane as an adjacent component 30 and 40. The slave pulley 56 is interconnected to the adjacent pulley 32 of the hydraulic pump 30 via the belt or chain 34 thereby forming a secondary section 62 of the drive train 50. The slave pulley 58 is interconnected to the adjacent pulley 42 of the compressor 40 via the belt or chain 44 thereby forming a tertiary section 64 of the drive train 50. Additional slave pulleys (not shown) may be fastened to the jack shaft 52 as desired in order to drive additional components (not shown) of the unit 10. As configured, the prime mover 20 drives both the hydraulic pump 30 and the compressor 40 via the jack shaft 52 and the various belts and pulleys of the drive train 50.

Referring now to FIG. 4, various additional features may be included to enhance the functionality of the unit 10. For example, as compression of the gas naturally increases the temperature of the gas, in one embodiment the compressor 40 is used in combination with an inline cooling unit 100. The inline cooling unit 100 is located on the second gas line 92 between the compressor 40 and the storage tank 110 so as to cool the gas prior to storing the gas in the storage tank 110. In one embodiment, the cooling unit 100 comprises a plurality of coils (not shown) and a fan 102, whereby the compressed gas is circulated through the plurality of coils and the fan 102 draws air through the coils thereby cooling the compressed gas. In another embodiment, the cooling unit 100 comprises a first set of coils (not shown), a second set of coils (not shown), a fan 102, and a coolant (not shown). As such, the first set of coils is submerged in the coolant, the compressed gas is circulated through the first set of coils, the coolant is circulated through the second set of coils, and the fan 102 forces or draws air through the second set of coils to remove excess heat from the second set of coils and the coolant. In another embodiment, the compressor 40 is further modified to include an electric generator 104 that is driven by the tertiary section 64 of the drive train 50. As such, the fan 102 of the cooling system 100 is powered by generator 104. In an alternate embodiment, an additional pulley (not shown) is attached to the jack shaft 52 at a position adjacent the fan 108, whereby the jack shaft 52 and the fan 108 are interconnected via a belt or chain 112 which drives the fan 108 in accordance with the cooling system 100. Further, in some embodiments fan 108 is driven by a hydraulic motor. One of skill in the art will appreciate that any cooling system known in the art may be successfully coupled with the compressor. For example, in one embodiment the compressor 40 and the cooling unit 100 are combined into a single unit and are commercially available as such.

Additional features may also include an oil-field separator 120 and a filtering unit 122. The oil-field separator 120 is commonly used in the oil industry and may include any device capable of reducing wellhead 12 pressure so that dissolved gas associated with hydrocarbon liquids is flashed off or separated as a separate phase for compression, cooling and storage. The oil-field separator 120 generally comprises a stock tank 124 or series of tanks interposed between the wellhead 12 the compressor 40. The stock tank 124 may further comprise a plurality of vents or valves 126 for diverting different phase materials into separate storage tanks or treatment processes.

A filtering unit 122 may further be interposed between the oil-field separator 120 and the compressor 40, as shown. The filtering unit 122 is provided to further homogenize the gaseous material entering the compressor 40 by removing debris or other unwanted materials. In some implementations of the current invention, the filtering unit 122 comprises a plurality of filtering units, the filtering units comprising varying sizes of porosity or filtering mediums to further homogenize the gas. One of skill in the art will appreciate that oil and gas filters are common in the gas and oil industry and therefore the present invention may be configured to utilize any filtering unit 122 suitable to achieve the purpose of the combination unit 10.

Referring now to FIGS. 1, 2 and 4, some embodiments of the combination unit 10 further comprises an enclosure 70, shown in phantom. The enclosure 70 may include any portion of the unit 10 and may also be configured to enclosure the wellhead 12, as shown in FIG. 4. The enclosure 70 is generally provided to prevent interference with the components and drive train 50 of the unit 10. Therefore, in one embodiment the enclosure 70 substantially and individually covers the drive train 50 and each component 20, 30, 40, 96, 100, 110, 120 of the unit 10. In another embodiment, the enclosure 70 substantially covers the unit 10 as a whole. In yet another embodiment, the enclosure 70 comprises a steel mesh thereby allowing ventilation for the various components of the unit 10, yet preventing tampering therewith. Finally, in one embodiment a portion of the enclosure 70 is substantially solid to protect the unit 10 from the elements.

The combination unit 10 may also include a platform or skid 72 upon which the various components of the unit 10 are situated and supported. As such, the unit 10 is portable and may initially be built off site and then installed at the wellhead 12 location. The skid 72 generally comprises a material, such as steel, and structure sufficient to withstand the weight of the individual components 20, 30, 40, 96, 100, 110, 120 as well as to provide a sturdy foundation upon which to support the components. In some embodiments, the skid 72 is configured to compatibly receive and support the enclosure 70.

The combination unit 10 of the present invention is provided to replace and/or augment current artificial lift systems, such as the jack pump. The unit 10 is solely driven by the prime mover 20, which may be powered by any source deemed necessary, as described above. The prime mover 20 is interconnected with the drive train 50 of the unit via a pulley 24 and a belt 26. The drive train 50 comprises a jack shaft 52 having a master pulley 54 coupled to the belt 26, and a plurality of slave pulleys 56 and 58 each being coupled to various components 30 and 40 of the unit via belts 34 and 44. The jack shaft 52 and the pulleys 54, 56, and 58 coupled thereto are rotated by the prime mover 20. As such, the slave pulleys 56 and 58 drive their respective components 30 and 40, thereby providing the actuation necessary for the components 30 and 40 to perform their function. The hydraulic pump 30 is driven thereby providing a circulation of hydraulic fluid to the hydraulic components of the subterranean pump, as described above. The compressor 40 is driven thereby providing sufficient compression to the gaseous material from the wellhead 12, effecting a phase change prior to storage in the storage tank 110. As configured, the single prime mover 20 is sufficient to drive all of the components of the unit 10, which in turn drives the subterranean pump associated with the wellhead 12. Thus, the combination unit 10 of the present invention overcomes the deficiencies inherent in the prior art.

Referring now to FIG. 5, the combination unit 10 may be bisected to provide a modular pump-driving system 200 and a separate pumping unit 210. The pump-driving system 200 generally comprises a prime mover 20 configured to drive a drive train 50, as previously disclosed. The drive train 50 comprises a plurality of pulleys and belts that are positioned to transfer torque from the prime mover 20 to the individual components of the pump-driving system 200. The components of the pump-driving system 200 include, but are not limited to, a compressor 40 and a hydraulic pump 30. As previously discussed, the hydraulic pump 30 is provided to drive a pump or pumping unit 210 associated with a subterranean well. In some embodiments, hydraulic lines 80 a and 80 b are coupled to the hydraulic pump 30 to facilitate ingress and egress of hydraulic fluid between the hydraulic pump 30 and hydraulic components of the pumping unit 210. In some embodiments, hydraulic lines 80 a and 80 b further include end couplings 180 that are adapted to permanently or temporarily couple the hydraulic lines 80 a and 80 b to a hydraulic portion of the pumping unit 210.

The pumping unit 210 generally comprises machinery and apparatus configured to lift oil or gas from a subterranean well via a wellhead 12. Referring to FIG. 5, some implementations of the present invention include a pumping unit 210 having a pumpjack 212. A pumpjack 212, also known as a walking beam pump or a nodding donkey pump, generally includes a scaffold 214 pivotally coupled to a beam 216. The beam 216 comprises a first end that is pivotally coupled to a pitman arm 220 which in turn is pivotally coupled to a counter weight 222. The beam 216 further comprises a second end that is fixedly coupled to a head 218, also known as a horse head. The head 218 is further coupled to a sucker line 224 which accesses the subterranean well via the wellhead 12. Specifics regarding the operation and mechanics of pumpjack are well known in the art.

In some embodiments of the present invention, the counter weight 222 of the pumpjack 212 is coupled to a hydraulic motor 230 via a chain or belt 226. The hydraulic motor 230 is configured to drive a pulley 232 which in turn drives or rotates a pulley portion 240 of the counter weight 222. The pulley portion 240 of the counter weight 222 is rotationally secured to a stator 250 via a rotor 252. As the pulley 232 of the hydraulic motor 230 rotates, the belt 226 rotates the pulley portion 240 of the counter weight 222 to rotate the counter weight 222. As the counter weight 222 rotates, the pitman arm 220 pivots the beam 216 relative to the scaffold 214. The pivoting action of the beam 216 causes the sucker line 224 to move vertically within the wellhead 12 to produce the well.

The hydraulic motor 230 is actuated by the hydraulic pump 30 via hydraulic lines 80 a and 80 b. In some embodiments, hydraulic lines 80 a and 80 b span extensive lengths to permit remote placement of the pumping unit 210 relative to the position of the pump driving system 200. In other embodiments, hydraulic lines 80 a and 80 b are spliced and coupled to multiple pumping units 210. As such, one pump driving unit 200 is utilized to drive multiple pumping units 210. Alternatively, in some embodiments hydraulic lines 80 a and 80 b are coupled to separate piece of equipment that is hydraulically driven but not a pumping unit 210. For example, in some embodiments hydraulic lines 80 a and 80 b are coupled to a subterranean pump. In other embodiments, hydraulic lines 80 a and 80 b are coupled to a hydraulic drill. Finally, one of skill in the art will appreciate that hydraulic lines 80 a and 80 b may be coupled to any hydraulic system both within and without the oil industry.

Referring now to FIG. 6, an integrated pump driving unit and pumping unit 300 is shown. The integrated unit 300 combines a pump driving unit 200 and a pumping unit 210 onto a single skid 72. As such, hydraulic lines 80 a and 80 b are excluded from the design and replaced by a belt or chain 62. The belt or chain 62 directly links the torque of the jack shaft 52 to the pulley 232 of a gear reducer 310. The gear reducer 310 further comprises a crank arm 312 having a first end that is directly coupled to a system of gears within the gear reducer 310. The crank arm further includes a second end that is directly coupled to the counter weight 222 of the pumpjack 212. Thus, as the jack shaft 52 rotates under the power of the prime mover 20, the pulley 232 of the gear reducer 310 is rotated at a determined speed. Gears (not shown) within the gear reducer 310 are configured to reduce the rotational speed of the pulley 232 to achieve a desired rotational speed for the crank arm 312. As the crank arm 312 rotates, the counterweight 222 rotates which moves the pitman arm 220 thereby transferring the rotation of the crank arm 312 and the counterweight 222 into a linear motion that drives the pumpjack 212.

Referring now to FIG. 7, an integrated pump driving unit 400 is shown. The integrated unit 400 combines a pump driving unit 200 and a pumping unit 210 onto a single skid 72. However, unlike integrated unit 300, integrated unit 400 comprises a hydraulic pump 30 that is coupled to the jack shaft 52 via a belt or chain 62. Additionally, integrated unit 400 includes hydraulic lines 80 a and 80 b coupling the hydraulic pump 30 to a hydraulic driven unit 402. Hydraulic driven unit 402 is provided to convert the hydraulic pressure from hydraulic lines 80 a and 80 b into rotational movement which rotates the counterweight 222 of the pumpjack 212. One of skill in the art will appreciate that the hydraulic driven unit 402 may include any hydraulically driven motor, pump, or device capable of driving a jackpump 212. For example, in some embodiments the hydraulic driven unit 402 comprises a hydraulic motor, similar to those discussed in connection with FIG. 5 above. In other embodiments, the hydraulic driven unit 402 comprises a second hydraulic pump. Finally, in some embodiments the hydraulic driven unit 402 comprises a hydraulic gear reducer.

One of skill in the art will appreciate that the hydraulic driven unit 402 may be used to accomplish tasks in addition to driving the pumpjack unit 212. For example, in some embodiments the hydraulic driven unit 402 is utilized to drive both the pumpjack unit 212 and a compressor. In other embodiments, the hydraulic driven unit 402 is utilized to drive both the pumpjack unit 212 and a subterranean pump.

Referring now to FIG. 8, a direct drive pump driving unit 500 is shown. In some embodiments, unit 500 comprises a prime mover 20 having an extended shaft or rotor 23 that is rotatably driven by the prime mover 20. Prime mover 20 may comprise any electric or petrol powered motor or engine, as previously discussed. In some embodiments, a portion of rotor 23 extends outwardly from prime mover 20 to operably intersect a first hydraulic pump 30. Thus, first hydraulic pump 30 is directly driven by rotor 23 or prime mover 20.

In some embodiments, hydraulic pump 30 is hydraulically coupled to a hydraulic motor 230 of a separate pumping unit 210 via hydraulic lines 80 a and 80 b, in accordance with previously discussed embodiments. Thus, in some embodiments pumping unit 210 is driven by hydraulic motor 230 which is hydraulically driven by hydraulic pump 30, wherein hydraulic pump 30 is directly driven by prime mover 20 via rotor 23. Accordingly, some embodiments of the present invention enable production of a pumping unit via a single prime mover 20, without requiring a system of belts and pulleys, as taught in some of the previous embodiments.

In some embodiments, pumping unit 210 comprises any form of hydraulically-driven artificial lift. Further, in some embodiments pumping unit 210 comprises at least one of an above-ground pump, a subterranean pump, and/or combinations thereof.

In some embodiments, direct drive pump unit 500 further comprises a second hydraulic pump 31 which is further driven by prime mover 20 via rotor 23. In some embodiments, hydraulic pump 31 is hydraulically coupled to a hydraulic motor 231 of a remotely located processing unit 550 via hydraulic lines 81 a and 81 b.

Hydraulic motor 231 is directly coupled to a compressor 40. Compressor 40 may include any type of compressor or device capable of compressing a product artificially lifted from well 12. In some embodiments, compressor 40 comprises a rotary screw compressor. In other embodiments, compressor 40 comprises a vain compressor. Further, in some embodiments compressor 40 comprises a reciprocating compressor.

In some embodiments, processing unit 550 further comprises in input scrubber or filtering unit 552 in fluid communication with well 12 and compressor 40 via gas line 90. Thus, a product lifted from the well 12 by the pumping unit 210 first passed through filtering unit 552 and then delivered to the compressor 40, wherein compressor 40 compresses the product prior to cooling the lifted the product.

In some embodiments, processing unit 550 further comprises an inline cooling unit 100 whereby the compressed product is cooled prior to storing the product or sending the product to a pipeline 111 via gas line 92. In some embodiments, processing unit 550 further comprises an outlet scrubber or filtering unit 554 which further filters and/or processes the compressed and cooled product prior to storage.

Direct drive pump unit 500 may further include additional hydraulic units 33 or other devices that are further driven by prime mover 20 via extended rotor 23. For example, in some embodiments direct drive pump unit 500 further comprises a plurality of additional units 33 for driving additional pumping units and/or cooling units (not shown), in accordance with the present invention. In other embodiments, additional unit 33 further comprises a device for executing a function related to artificially lifting a product from well 12, as described above. Still further, in some embodiments additional unit 33 comprises greater than five additional units, each unit being operated by prime mover 20 via extended rotor 23. Some embodiments of the present system further include an enclosure, wherein each component 500, 550 and 210 is independently enclosed, in accordance with an enclosure as described above.

The direct drive pump unit 500 of the present invention enables a user to utilize a single prime mover 20 to artificially lift a product from a well 12 remotely located from the direct drive pump unit 500. Further, the direct drive pump unit 500 enables a user to utilize a single prime mover 20 to process an artificially lifted product at a processing unit 550 located remotely from the direct drive pump unit 500. Thus, the direct drive pump unit 500 may be safely used in combination with a pumping unit 210 and a processing unit 550 in accordance with safety rules and regulations within the oil and gas industries. For example, in some embodiments the present invention utilizes a direct drive system that is compliant with class I, division II regulations, as known in the art.

The present invention may be embodied in other specific forms without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the invention is, therefore, indicated by the appended claims rather than by the foregoing description. All changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope. 

1. A pump driving system, comprising: a direct drive pump driving unit comprising a prime mover having a rotating shaft operably coupled to a first hydraulic pump and a second hydraulic pump; a pumping unit remotely located from the direct drive remote pump driving unit, a hydraulic motor of the pumping unit being hydraulically coupled to the first hydraulic pump, the hydraulic motor of the pumping unit further being operably coupled to an artificial lift whereby the hydraulic motor of the pumping unit drives the artificial lift; a processing unit remotely located from the direct drive remote pump driving unit and from the pumping unit, a hydraulic motor of the cooling unit further being operably coupled to a compressor of the cooling unit, wherein a lifted material from the pumping unit is process through the cooling unit prior to being stored.
 2. The system of claim 1, further comprising a hydraulic line hydraulically coupling the first hydraulic pump and the second hydraulic pump to the hydraulic motor of the pumping unit and the hydraulic motor of the processing unit, respectively.
 3. The system of claim 1, further comprising a gas line in fluid communication with the compressor and a wellhead.
 4. The system of claim 3, further comprising an oil-field separator in fluid communication with the gas line.
 5. The system of claim 3, further comprising an inlet scrubber in fluid communication with the gas line.
 6. The system of claim 1, wherein the prime mover is selected from the group consisting of a natural gas engine, a diesel engine, a petrol engine, a gas turbine, a water turbine, and an electric motor.
 7. The system of claim 3, further comprising a cooling unit in fluid communication with the gas line.
 8. The system of claim 1, further comprising an enclosure surrounding at least one of the direct drive pump driving unit, the pumping unit, and the processing unit.
 9. The system of claim 1, further comprising a pipeline in fluid communication with the gas line.
 10. The system of claim 6, wherein the electric motor is powered by a battery.
 11. The system of claim 6, wherein the electric motor is powered by an alternate power source selected from the group consisting of a hydro-powered generator, a solar-powered generator, a wind-powered generator, a geothermal powered generator, and an electrical power line.
 12. A method for driving an above ground pump, the method comprising: providing a direct drive pump driving unit comprising a prime mover having a rotating shaft operably coupled to a first hydraulic pump and a second hydraulic pump; operably coupling the first hydraulic pump to a hydraulic motor of a remotely located pumping unit, wherein the prime mover drives the hydraulic motor of the remotely located pumping unit via the first hydraulic pump to artificially lift a product from a well; operably coupling the second hydraulic pump to a hydraulic motor of a remotely located processing unit, wherein the prime mover drives the hydraulic motor of the remotely located processing unit via the second hydraulic pump, and wherein the hydraulic motor of the remotely located processing unit drives a compressor of the processing unit to compress the lifted product from the well; providing fluid communication between the well and the compressor via a gas line, wherein the pumping unit is actuated by the prime mover via the first hydraulic pump to artificially lift the product from the well and into the gas line, whereafter the product is compressed by compressor, the compressor being actuated by the prime mover via the second hydraulic pump and the hydraulic motor of the remotely located processing unit.
 13. The method of claim 12, further comprising the steps of: hydraulically coupling the first hydraulic pump to the hydraulic motor of the remotely located pumping unit via a first hydraulic line; and hydraulically coupling the second hydraulic pump to the hydraulic motor of the remotely located processing unit via a second hydraulic line.
 14. The method of claim 13, further comprising the step of interposing an inlet scrubber between the well and the compressor via the gas line.
 15. The method of claim 13, further comprising the step of interposing an outlet scrubber between the compressor and the pipeline via the gas line.
 16. The method of claim 13, further comprising the step of collecting the compressed product in at least one of a storage tank and a pipeline in fluid communication with the compressor.
 17. The method of claim 16, further comprising the step of cooling the compressed product prior to collecting the compressed product in at least one of the storage tank and the pipeline.
 18. The method of claim 17, wherein the compressor is at least one of a rotary screw compressor, a vain compressor, and a reciprocating compressor.
 19. The method of claim 12, wherein the pumping unit is at least one of an above-ground pumping unit and a subterranean pumping unit.
 20. A modular pumping unit, comprising: a direct drive pump driving unit comprising a prime mover having an extended rotating shaft operably coupled to a first hydraulic pump and a second hydraulic pump; a pumping unit remotely located from the direct drive pump driving unit, a hydraulic motor of the pumping unit being hydraulically coupled to the first hydraulic pump, the hydraulic motor of the pumping unit being hydraulically coupled to the first hydraulic pump, the hydraulic motor of the pumping unit further being operably coupled to an artificial lift whereby the hydraulic motor of the pumping unit drives the artificial lift to lift a product from a well.
 21. The modular pumping unit of claim 20, further comprising a processing unit remotely located from the direct drive pump driving unit and further remotely located from the pumping unit, wherein the processing unit comprises a hydraulic motor that is operably coupled to the second hydraulic pump, wherein the hydraulic motor of the processing unit drives at least one component selected from the group consisting of a compressor, an oil-field separator, an inlet scrubber, an outlet scrubber, a filtering unit, a cooling unit, a generator, a battery, and an alternative power source.
 22. The modular pumping unit of claim 20, wherein the artificial lift is at least one of an above ground pump and a subterranean pump.
 23. The modular pumping unit of claim 21, further comprising a gas line fluidly interconnecting the well and the compressor, wherein the first hydraulic pump drives the hydraulic motor of the artificial lift to artificially lift the product from the well, through the gas line, and to the compressor fluidly coupled thereto. 